HIGHPOINT RESOURCES CORPORATION Introduction
The following discussion and analysis should be read in conjunction with the "Selected Historical Financial Information" and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward -looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;" "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;" and "Item 1A. Risk Factors" above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law. Overview We develop oil and natural gas in theRocky Mountain region ofthe United States . We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.
We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration
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The following table summarizes the estimated net proved reserves and related
Standardized Measure for the years indicated. The Standardized Measure is not
intended to represent the current market value of our estimated oil and natural
gas reserves.
Year Ended December 31,
2020 2019 2018
Estimated net proved reserves (MMBoe) 50.8 127.4 104.6
Standardized measure (1) (in millions)
(1)December 31, 2020 reserves were based on average prices of$39.54 WTI per Bbl of oil,$1.99 Henry Hub per Mcf of natural gas and a percentage of the of the average oil price per Bbl of NGL.December 31, 2019 reserves were based on average prices of$55.85 WTI for oil,$2.58 Henry Hub for natural gas and a percentage of the of the average oil price per Bbl of NGL.December 31, 2018 reserves were based on average prices of$65.56 WTI for oil,$3.10 Henry Hub for natural gas and$32.71 for NGLs. In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the "COVID-19 pandemic"). As the virus spread, global economic activity began to slow resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year endedDecember 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. As ofFebruary 4, 2021 , we have hedged 3,098,000 barrels and 365,000barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively. However, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. This uncertainty increases the volatility and amplitude of risks we face as described in "Item 1A. Risk Factors". If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021. We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the "Going Concern" section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of$140.0 million as ofDecember 31, 2020 . This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of$625.0 million as ofDecember 31, 2020 . We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern. We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in theRocky Mountain region ofthe United States . Consequently, we currently report a single reportable segment. 38
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Significant Business DevelopmentsPending Merger with Bonanza Creek Energy, Inc.
OnNovember 9, 2020 , we entered into a Merger Agreement with Bonanza Creek in which HighPoint's debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. The Merger is expected to close in the first quarter of 2021 under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. HighPoint paid Bonanza Creek a transaction expense fee of$6.0 million in cash in consideration upon signing the Merger Agreement with Bonanza Creek. The Merger Agreement requires HighPoint to pay Bonanza Creek a termination fee of$15.0 million , less the$6.0 million transaction expense fee previously paid, if the agreement is terminated under certain circumstances as defined by the Merger Agreement. See "Items 1 and 2 Business and Properties - Business - Significant Business Developments" for additional information. 39
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Results of Operations
Year Ended
The following table sets forth selected operating data for the periods
indicated:
Year Ended December 31, Increase (Decrease)
2020 2019 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues:
Oil, gas and NGL production $ 249,192 $ 452,274 $ (203,082) (45) %
Other operating revenues, net 1,155 385 770 200 %
Total operating revenues $ 250,347 $ 452,659 $ (202,312) (45) %
Operating Expenses:
Lease operating expense $ 32,548 $ 37,796 $ (5,248) (14) %
Gathering, transportation and processing expense 18,467 10,685 7,782 73 %
Production tax expense (1) (630) 23,541 (24,171) *nm
Exploration expense 192 143 49 34 %
Impairment and abandonment expense 1,285,085 9,642 1,275,443 *nm
Loss on sale of properties 4,777 2,901 1,876 65 %
Depreciation, depletion and amortization 148,995 321,276 (172,281) (54) %
Unused commitments 18,807 17,706 1,101 6 %
General and administrative expense (2) 43,167 44,759 (1,592) (4) %
Merger transaction expense 25,891 4,492 21,399 476 %
Other operating expenses (income), net (544) 402 (946) *nm
Total operating expenses $ 1,576,755 $ 473,343 $ 1,103,412 233 %
Production Data:
Oil (MBbls) 5,909 7,668 (1,759) (23) %
Natural gas (MMcf) 16,428 16,614 (186) (1) %
NGLs (MBbls) 2,352 2,101 251 12 %
Combined volumes (MBoe) 10,999 12,538 (1,539) (12) %
Daily combined volumes (Boe/d) 30,052 34,351 (4,299) (13) %
Average Realized Prices before Hedging:
Oil (per Bbl) $ 34.62 $ 52.86 $ (18.24) (35) %
Natural gas (per Mcf) 1.33 1.56 (0.23) (15) %
NGLs (per Bbl) 9.69 10.00 (0.31) (3) %
Combined (per Boe) 22.66 36.07 (13.41) (37) %
Average Realized Prices with Hedging:
Oil (per Bbl) $ 53.25 $ 54.39 $ (1.14) (2) %
Natural gas (per Mcf) 1.30 1.50 (0.20) (13) %
NGLs (per Bbl) 9.69 10.00 (0.31) (3) %
Combined (per Boe) 32.62 36.92 (4.30) (12) %
Average Costs (per Boe):
Lease operating expense $ 2.96 $ 3.01 $ (0.05) (2) %
Gathering, transportation and processing expense 1.68 0.85 0.83 98 %
Production tax expense (1) (0.06) 1.88 (1.94) *nm
Depreciation, depletion and amortization 13.55 25.62 (12.07) (47) %
General and administrative expense (2) 3.92 3.57 0.35 10 %
*Not meaningful.
40-------------------------------------------------------------------------------- Table of Contents (1)See explanation of negative production tax expense for the year endedDecember 31, 2020 under Production Tax Expense below. (2)Included in general and administrative expense is long-term cash and equity incentive compensation of$3.5 million (or$0.32 per Boe) and$8.6 million (or$0.69 per Boe) for the years endedDecember 31, 2020 and 2019, respectively. Production Revenues and Volumes. Production revenues decreased to$249.2 million for the year endedDecember 31, 2020 from$452.3 million for the year endedDecember 31, 2019 . The decrease in production revenues was due to a 37% decrease in the average realized prices per Boe before hedging, as well as a 12% decrease in production volumes. The decrease in average realized prices per Boe before hedging decreased production revenues by approximately$168.2 million , while the decrease in production volumes decreased production revenues by approximately$34.9 million .
Total production volumes of 11.0 MMBoe for the year ended
Lease Operating Expense ("LOE"). LOE decreased to $2.96 per Boe for the year
ended December 31, 2020 from $3.01 per Boe for the year ended December 31, 2019 .
The decrease per Boe for the year ended December 31, 2020 compared with the year
ended December 31, 2019 is primarily related to operational efficiencies and a
decrease in service industry costs due to a downturn in the industry.
Gathering, Transportation and Processing ("GTP") Expense. GTP expense increased
to $1.68 per Boe for the year ended December 31, 2020 from $0.85 per Boe for the
year ended December 31, 2019 .
Costs incurred to gather, transport and/or process our oil, gas and NGLs prior
to the transfer of control to the customer are included in GTP expense. Costs
incurred to gather, transport and/or process our oil, gas and NGLs after control
has transferred to the customer are considered components of the consideration
received from the customer and thus recorded in oil, gas and NGL production
revenues. In general, based on specific contract arrangements, costs incurred
associated with gas and NGLs in the Hereford Field are included in GTP expense
and costs incurred associated with gas and NGLs in the Northeast Wattenberg
Field are primarily included in production revenues. Costs incurred associated
with oil are included in production revenues for both areas. See the "Revenue
Recognition" section in Note 2 of the notes to the consolidated financial
statements for additional information.
The increase in GTP per Boe for the year ended December 31, 2020 compared to
2019 was due to an increase from the Hereford Field associated with an
unfavorable contract assumed in the 2018 Merger. The unfavorable contract
amortization reduced GTP in 2019, but was fully amortized by the end of 2019
resulting in unfavorable contract pricing throughout 2020.
Production Tax Expense. Total production taxes decreased to negative $0.6
million for the year ended December 31, 2020 from $23.5 million for the year
ended December 31, 2019 . Production taxes are primarily based on the wellhead
values of production, which exclude gains and losses associated with hedging
activities. Production tax expense for both periods included an annual true up
of Colorado ad valorem and severance tax based on actual assessments. Production
taxes for the year ended December 31, 2020 also included a reduction of $5.4
million due to a change in estimate associated with our 2019 Colorado ad valorem
tax that is due in 2021 and Colorado severance tax refunds of $1.8 million based
on an audit of tax years 2015 to 2017. Excluding the ad valorem adjustments and
the severance tax refunds associated with tax years 2015 to 2017, production
taxes as a percentage of oil, natural gas and NGL sales before hedging
adjustments were 6.5% and 6.3% for the years ended December 31, 2020 and 2019,
respectively.
Impairment and Abandonment Expense. Market conditions led to a decline in the
recoverability of the carrying value of our oil and gas properties during the
quarter ended March 31, 2020 . Since the carrying amount of our oil and gas
properties was no longer recoverable, we impaired the carrying value to fair
value. Therefore, we recognized non-cash impairment charges of $1.2 billion
associated with proved oil and gas properties and $76.3 million associated with
unproved oil and gas properties. In addition, as the result of our continuous
review of our acreage position and future drilling plans, we recognized non-cash
impairment related to our unproved oil and gas properties in the amount of
$17.9 million during 2020 associated with certain leases in which the economics
may not support renewal or extending at current contracted values. Our
impairment and abandonment expense for the year ended December 31, 2020 and 2019
is summarized below:
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Year Ended December 31,
2020 2019
(in thousands)
Impairment of proved oil and gas properties $ 1,188,566 $ -
Impairment of unproved oil and gas properties 94,209
3,854
Abandonment expense 2,310
5,788
Total impairment and abandonment expense$ 1,285,085 $
9,642
We will continue to review our acreage position and future drilling plans as
well as assess the carrying value of our properties relative to their estimated
fair values. Lower sustained commodity prices or additional commodity price
declines may lead to additional property impairment in future periods.
Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $149.0
million for the year ended December 31, 2020 compared with $321.3 million for
the year ended December 31, 2019 . The decrease of $172.3 million was the result
of a 47% decrease in the DD&A rate and a 12% decrease in production for the year
ended December 31, 2020 compared with the year ended December 31, 2019 . The
decrease in the DD&A rate accounted for a $132.9 million decrease in DD&A
expense while the decrease in production accounted for a $39.4 million decrease
in DD&A expense.
Under successful efforts accounting, depletion expense is calculated using the
units-of-production method on the basis of some reasonable aggregation of
properties with a common geological structural feature or stratigraphic
condition, such as a reservoir or field. The capital expenditures for proved
properties for each field compared to the proved reserves corresponding to each
producing field determine a depletion rate for current production. For the year
ended December 31, 2020 , the relationship of historical capital expenditures,
proved reserves and production from certain producing fields yielded a depletion
rate of $13.55 per Boe compared with $25.62 per Boe for the year ended
December 31, 2019 . The decrease in the depletion rate of 47% was a result of
recognizing a $1.2 billion impairment associated with our proved oil and gas
properties during the quarter ended March 31, 2020 .
Unused Commitments. Unused commitments expense of $18.8 million and $17.7
million for the years ended December 31, 2020 and 2019, respectively, primarily
related to gas transportation contracts. During March 2010 , we entered into two
firm natural gas pipeline transportation contracts to provide a guaranteed
outlet for production from the West Tavaputs area of the Uinta Basin and the
Gibson Gulch area of the Piceance Basin . These transportation contracts were not
included in the sales of these assets in December 2013 and September 2014 ,
respectively. Both firm transportation contracts require the pipeline to provide
transportation capacity and require us to pay monthly transportation charges
regardless of the amount of pipeline capacity utilized. The agreements expire
July 31, 2021 .
General and Administrative Expense. General and administrative expense decreased
to $43.2 million for the year ended December 31, 2020 from $44.8 million for the
year ended December 31, 2019 . General and administrative expense on a per Boe
basis increased to $3.92 for the year ended December 31, 2020 from $3.57 for the
year ended December 31, 2019 . The decrease in general and administrative expense
for the year ended December 31, 2020 was due to a decrease in long-term cash and
equity incentive compensation discussed below, partially offset by an increase
in legal and advisory fees associated with strategic plans that were
contemplated, but not completed. Legal and advisory fees that resulted in the
Merger Agreement discussed in Note 1 of the notes to the consolidated financial
statements were recognized in merger transaction expense discussed below.
Included in general and administrative expense is long-term cash and equity
incentive compensation of $3.5 million and $8.6 million for the years ended
December 31, 2020 and 2019, respectively. The decrease for the year ended
December 31, 2020 was primarily due to a reduction in overall equity awards
granted during the year ended December 31, 2020 . In addition, we cancelled all
performance cash units during the year ended December 31, 2020 . The components
of long-term cash and equity incentive compensation for each of the years ended
December 31, 2020 and 2019 are shown in the following table:
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Year Ended December 31,
2020 2019
(in thousands)
Nonvested common stock $ 4,106 $ 6,601
Nonvested common stock units 543 1,177
Nonvested performance cash units (1) (1,162) 844
Total $ 3,487 $ 8,622 (1)The nonvested performance cash units are accounted for as liability awards.
The expense for the period will increase or decrease based on updated fair
values of these awards at each reporting date. As of
Merger Transaction Expense. Merger transaction expense was$25.9 million and$4.5 million for the years endedDecember 31, 2020 andDecember 31, 2019 , respectively. Transaction expenses included consulting, advisory, legal and other merger-related fees associated with the Merger Agreement for the yearDecember 31, 2020 and the 2018 Merger for the year endedDecember 31, 2019 . See Note 4 of the notes to the consolidated financial statements for additional information. Commodity Derivative Gain (Loss). Commodity derivative gain was$124.9 million for the year endedDecember 31, 2020 compared with a loss of$99.0 million for the year endedDecember 31, 2019 . The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as ofDecember 31, 2020 and 2019 or during the periods then ended. The fair value of our open but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
Year Ended December 31,
2020 2019
(in thousands)
Realized gain (loss) on derivatives (1) $ 109,583 $ 10,667 Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
495 (81,166)
Unrealized gain (loss) on derivatives (1) 14,847 (28,454)
Total commodity derivative gain (loss) $ 124,925 $ (98,953)
(1)Realized and unrealized gains and losses on commodity derivatives are
presented herein as separate line items but are combined for a total commodity
derivative gain (loss) in the Consolidated Statements of Operations. This
separate presentation is a non-GAAP measure. Management believes the separate
presentation of the realized and unrealized commodity derivative gains and
losses is useful because the realized cash settlement portion provides a better
understanding of our hedge position. We also believe that this disclosure allows
for a more accurate comparison to our peers.
In 2020, approximately 91% of our oil volumes and 33% of our natural gas volumes
were subject to financial hedges, which resulted in an increase in oil income of
$110.1 million and a decrease in natural gas income of $0.5 million after
settlements. In 2019, approximately 88% of our oil volumes and 19% of our
natural gas volumes were covered by financial hedges, which resulted in an
increase in oil income of $11.7 million and a decrease natural gas income of
$1.0 million after settlements.
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Income Tax (Expense) Benefit. For the year ended December 31, 2020 , as a result
of the $1.3 billion impairment, we determined that it was not more likely than
not that we would be able to realize existing deferred tax assets. This
determination was made by considering all available evidence in assessing the
need for a valuation allowance. Such evidence included the scheduled reversal of
deferred tax liabilities and current and projected future taxable income and tax
planning strategies. In making this assessment, judgment is required in
considering the relative weight of negative and positive evidence. As a result
of the analysis conducted, we recorded an income tax benefit of $95.9 million . A
$1.6 million deferred tax liability has been recorded for projected taxable
income in future periods in which only 80% of taxable income can be offset by
net operating losses.
For the year ended December 31, 2019 , we determined it was more likely than not
that we would be able to realize a portion of our deferred tax assets. This
determination was made by considering all available evidence in assessing the
need for a valuation allowance. Such evidence included the scheduled reversal of
deferred tax liabilities, assets acquired in connection with the 2018 Merger and
their classification as proved or unproved, current and projected future taxable
income and tax planning strategies.
Year Ended
A discussion of our results of operations for the year endedDecember 31, 2019 compared withDecember 31, 2018 can be found in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section of our Annual Report on Form 10-K for the year endedDecember 31, 2019 . Capital Resources and Liquidity
Current Financial Condition and Liquidity
We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the "Going Concern" section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of$140.0 million as ofDecember 31, 2020 . This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of$625.0 million as ofDecember 31, 2020 . We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern. In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a "going concern" ("going concern opinion") in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion. AtDecember 31, 2020 , we had cash and cash equivalents of$24.7 million and$140.0 million outstanding under the Credit Facility. AtDecember 31, 2019 , we had cash and cash equivalents of$16.4 million and$140.0 million outstanding under our Credit Facility. As part of our regular semi-annual redeterminations, the elected commitment amount on our Credit Facility was reduced to$300.0 million onMay 21, 2020 and to$185.0 million onNovember 3, 2020 . Our available borrowing capacity as ofDecember 31, 2020 was$24.0 million , after taking into account$21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations.
Sources of Liquidity and Capital Resources
Our primary sources of liquidity since our formation have been net cash provided
by operating activities, including commodity hedges, sales and other issuances
of equity and debt securities, bank credit facilities and sales of interests in
properties. Our primary use of capital has been for the development, exploration
and acquisition of oil and natural gas properties. As we pursue profitable
reserves and production growth, we continually monitor the capital resources
available to us to meet our future financial obligations, fund planned capital
expenditure activities and ensure adequate liquidity.
We may from time to time seek to retire, purchase or otherwise refinance our
outstanding debt securities through cash purchases and/or exchanges, in open
market purchases, privately negotiated transactions, exchange offers or
otherwise. Any
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such transactions will depend on prevailing market conditions, our liquidity
requirements, contractual restrictions and other factors. On November 9, 2020 ,
we entered into a Merger Agreement with Bonanza Creek pursuant to which
HighPoint's debt will be restructured and HighPoint will merge with a wholly
owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as
the surviving company following the merger and continuing as a wholly owned
subsidiary of Bonanza Creek. The Merger is expected to close in the first
quarter under the Exchange Offer or in the first or second quarter of 2021 under
the Prepackaged Plan. See "Items 1 and 2 Business and Properties - Business -
Significant Business Developments" for additional information.
Our future success in growing proved reserves and production will be highly
dependent on capital resources being available to us. Given the levels of market
volatility and disruption due to the COVID-19 pandemic and other recent macro
and microeconomic factors, the availability of funds from those markets has
diminished substantially. Further, arising from concerns about the stability of
financial markets generally and the solvency of borrowers specifically, the cost
of accessing the credit markets has increased as many lenders have raised
interest rates, enacted tighter lending standards, or altogether ceased to
provide funding to borrowers.
Cash Flow from Operating Activities
Net cash provided by operating activities was$129.0 million ,$278.6 million and$231.4 million in 2020, 2019 and 2018, respectively. The changes in net cash provided by operating activities are discussed above in "Results of Operations". The decrease in cash provided by operating activities from 2019 to 2020 was primarily due to a decrease in production revenues and a decrease in working capital changes due to the timing of cash receipts and disbursements, partially offset by an increase in cash settlements of derivatives.
Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict. To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap, swaption and cashless collar contracts to receive fixed prices for a portion of our production. AtDecember 31, 2020 , we had in place crude oil swaps covering portions of our 2021 and 2022 production, natural gas swaps covering portions of our 2021 and 2022 production, oil roll swaps covering portions of our 2021 and 2022 production, crude oil swaptions covering portions of our 2022 production and natural gas cashless collars covering portions of our 2021 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement. All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.
The following table includes all hedges entered into through
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Total Weighted Weighted Weighted
Hedged Quantity Average Fixed Average Floor Average Ceiling Index
Contract Volumes Type Price Price Price Price (1)
Swaps
2021
Oil 3,098,000 Bbls $ 54.30 WTI
Natural Gas 5,790,000 MMBtu $ 2.13 NWPL
2022
Oil 365,000 Bbls $ 50.15 WTI
Natural Gas 3,650,000 MMBtu $ 2.13 NWPL
Oil Roll Swaps (2)
2021
Oil 1,554,500 Bbls $ 0.14 WTI
2022
Oil 730,000 Bbls $ 0.22 WTI
Swaptions (3)
2022
Oil 1,092,000 Bbls $ 55.08 WTI
Cashless Collars
2021
Natural Gas 1,800,000 MMBtu $ 2.00 $ 4.25 NWPL
(1)WTI refers to West Texas Intermediate price as quoted on the New York
Mercantile Exchange . NWPL refers to the Northwest Pipeline Corporation price as
quoted in Platt's Inside FERC on the first business day of each month.
(2)These contracts establish a fixed amount for the differential between the
NYMEX WTI calendar month average and the physical crude oil delivery month
price. The weighted average differential represents the amount of reduction to
NYMEX WTI prices for the notional volumes covered by the swap contracts.
(3)These swaptions may become effective fixed-price swaps at the counterparty's
election on December 31, 2021 .
By removing the price volatility from a portion of our oil revenue, we have
mitigated, but not eliminated, the potential effects of changing prices on our
operating cash flow for the relevant period. While mitigating negative effects
of falling commodity prices, these derivative contracts also limit the benefits
we would receive from increases in commodity prices.
It is our policy to enter into derivative contracts with counterparties that are
lenders in the Credit Facility, affiliates of lenders in the Credit Facility or
potential lenders in the Credit Facility. Our derivative contracts are
documented using an industry standard contract known as a Schedule to the Master
Agreement and International Swaps and Derivative Association, Inc. ("ISDA")
Master Agreement or other contracts. Typical terms for these contracts include
credit support requirements, cross default provisions, termination events and
set-off provisions. We are not required to provide any credit support to our
counterparties other than cross collateralization with the properties securing
the Credit Facility. We have set-off provisions in our derivative contracts with
lenders under our Credit Facility which, in the event of a counterparty default,
allow us to set-off amounts owed to the defaulting counterparty under the Credit
Facility or other obligations against monies owed to us under the derivative
contracts. Where the counterparty is not a lender under the Credit Facility, we
may not be able to set-off amounts owed by us under the Credit Facility, even if
such counterparty is an affiliate of a lender under such facility.
Capital Expenditures
Our capital expenditures are summarized in the following tables for the periods
indicated:
Year Ended December 31,
Basin/Area 2020 2019 2018
(in millions)
DJ $ 97.3 $ 355.0 $ 508.2
Other 2.2 6.0 0.7
Total (1)(2) $ 99.5 $ 361.0 $ 508.9
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Year Ended December 31,
2020 2019 2018
(in millions) Acquisitions of proved and unproved properties and other real estate
$ -
95.5 319.3 448.9
Gathering and compression facilities 2.8 20.4 37.1
Geologic and geophysical costs 0.6 12.0 2.3
Furniture, fixtures and equipment 0.6 4.6 0.7
Total (1)(2) $ 99.5 $ 361.0 $ 508.9
(1)Includes exploration and abandonment expense, which are expensed under
successful efforts accounting, of $2.5 million , $5.9 million and $0.8 million
for the years ended December 31, 2020 , 2019 and 2018, respectively.
(2)Excludes $716.2 million related to the proved and unproved oil and gas
properties and furniture, equipment and other assets acquired in the 2018 Merger
for the year ended December 31, 2018 .
Our current estimated capital expenditure budget for the first quarter of 2021
is approximately $3.0 million , primarily associated with flowback on previously
completed wells. In addition, in November 2020 we entered into the Merger
Agreement with Bonanza Creek, which restricts our near-term capital spending
levels and does not allow for drilling or completion operations.
Capital expenditures decreased to $99.5 million for the year ended December 31,
2020 from $361.0 million for the year ended December 31, 2019 . The decrease was
due to a reduction in planned development for 2020 as well as deferring drilling
and completion activity starting in May 2020 due to the COVID-19 pandemic.
Capital expenditures for acquisitions of proved and unproved properties and
other real estate were $4.7 million for the year ended December 31, 2019 . This
was primarily related to acquisitions of proved and unproved properties in the
DJ Basin . The decrease in drilling, development, exploration and exploitation of
oil and natural gas properties to $319.3 million for the year ended December 31,
2019 from $448.9 million for the year ended December 31, 2018 was primarily
related to a decrease in development drilling and completion activities within
the DJ Basin . The increase in geologic and geophysical costs to $12.0 million
for the year ended December 31, 2019 from $2.3 million for the year ended
December 31, 2018 is related to activity in the Hereford field.
Financing Activities
Our outstanding debt is summarized below:
As of December 31, 2020 As of December 31, 2019
Debt Issuance Carrying Debt Issuance Carrying
Maturity Date Principal Costs Amount Principal Costs Amount
(in thousands)
Amended Credit Facility September 14, 2023 $ 140,000 $ - $ 140,000 $ 140,000 $ - $ 140,000
7.0% Senior Notes October 15, 2022 350,000 (1,535) 348,465 350,000 (2,372) 347,628
8.75% Senior Notes June 15, 2025 275,000 (3,031) 271,969 275,000 (3,717) 271,283
Total Long-Term Debt (1) $ 765,000 $ (4,566) $ 760,434 $ 765,000 $ (6,089) $ 758,911 (1)See Note 5 of the notes to the consolidated financial statements for additional information.
Credit Facility. OnMay 21, 2020 , as part of a regular semi-annual redetermination, our Credit Facility was amended. Among other things, the amendment decreased the aggregate elected commitment amount and the borrowing base from$500.0 million to$300.0 million , increased the applicable margins for interest and commitment fee rates and added provisions requiring the availability under the Credit Facility to be at least$50.0 million and the Company's weekly cash balance (subject to certain exceptions) to not exceed$35.0 million . OnNovember 2, 2020 , as part of another regular semi-annual redetermination, the Credit Facility was further amended. Among other things, the amendment reduced the Company's aggregate elected commitment amount to$185.0 million , reduced the borrowing base to$200.0 million and removed the provisions requiring availability under the Credit Facility to be at least$50.0 million . In addition, provisions were amended to 47 -------------------------------------------------------------------------------- Table of Contents prohibit the Company from incurring any additional indebtedness. The Company had$140.0 million outstanding as of bothDecember 31, 2020 andDecember 31, 2019 . The Company's available borrowing capacity under the Credit Facility as ofDecember 31, 2020 was$24.0 million , after taking into account$21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations. Our available borrowing capacity as of the date of this filing,February 24, 2021 , was$34.9 million , after taking into account outstanding irrevocable letters of credit of$18.1 million . While the stated maturity date in the Credit Facility isSeptember 14, 2023 , the maturity date is accelerated if we have more than$100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Credit Facility) that matures prior toDecember 14, 2023 . If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature onOctober 15, 2022 , the aggregate amount of those notes exceeds$100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, orJuly 16, 2022 . The borrowing base is determined at the discretion of the lenders and is subject to regular redetermination around April and October of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. If the borrowing base is reduced below the then-outstanding amount under the Credit Facility, we will be required to repay the excess of the outstanding amount over the borrowing base over a period of four months. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt. Going Concern. We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the "Going Concern" section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of$140.0 million as ofDecember 31, 2020 . This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of$625.0 million as ofDecember 31, 2020 . We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern. In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a "going concern" ("going concern opinion") in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion. Guarantor Structure. The issuer of our 7.0% Senior Notes and 8.75% Senior Notes isHighPoint Operating Corporation (f/k/aBill Barrett ), or the Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the 2018 Merger,HighPoint Resources Corporation , or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes inMarch 2018 . In addition,Fifth Pocket Production, LLC , or the Subsidiary Guarantor, became a subsidiary of Subsidiary Issuer onAugust 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. We have no other subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor. InMarch 2020 , theSEC issued a final rule, Financial Disclosures About Guarantors and Issuers ofGuaranteed Securities andAffiliates Whose Securities Collateralize a Registrant's Securities, which amends the disclosure requirements related to certain registered securities which currently require separate financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. Alternative disclosures are available for each subsidiary issuer/guarantor when they are consolidated and the parent company either issues or guarantees, on a full and unconditional basis, the guaranteed securities. If a registrant qualifies for alternative disclosure, the registrant may omit summarized financial information when not material and instead provide narrative disclosure of the guarantor structure, including terms and conditions of the guarantees. 48 -------------------------------------------------------------------------------- Table of Contents We qualify for alternative disclosure, and therefore, we are no longer presenting condensed consolidating financial information for the Parent Guarantor, Subsidiary Issuer, or the Subsidiary Guarantor of our debt securities. The assets, liabilities and results of operations of the issuer and guarantors of the guaranteed securities on a combined basis are not materially different than corresponding amounts presented in the consolidated financial statements of the Parent Guarantor as all of the material operating assets and liabilities, and all of our material operations reside within the subsidiary issuer. Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies.Moody's Investor Services andStandard & Poor's Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Credit Facility, the 7.0% Senior Notes or the 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities could be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations. A summary of our contractual obligations as of and
subsequent to
Payments Due By Year
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
(in thousands)Notes payable (1)(2)$ 306 $ -$ 140,000 $ - $ - $ -$ 140,306 7.0% Senior Notes (2)(3) 24,500 374,500 - - - - 399,000 8.75% Senior Notes (2)(4) 24,063 24,063 24,063 24,063 287,031 - 383,283 Firm transportation agreements (5) 19,549 13,064 14,600 14,640 4,800 -
66,653
Asset retirement obligations (6) 2,020 2,000 2,020 2,114 2,406 16,285 26,845 Derivative liability (7) 1,414 2,887 - - - - 4,301 Operating leases (8) 2,691 2,413 2,167 2,078 2,196 5,380 16,925 Other (9) 3,651 11,485 16,345 - - - 31,481 Total$ 78,194 $ 430,412 $ 199,195 $ 42,895 $ 296,433 $ 21,665 $ 1,068,794 (1)Included in notes payable is the outstanding principal amount under our Credit Facility dueSeptember 14, 2023 . This table does not include future commitment fees, interest expense or other fees on our Credit Facility because the Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. While the stated maturity date in the Credit Facility isSeptember 14, 2023 , the maturity date is accelerated if we have more than$100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Credit Facility) that matures prior toDecember 14, 2023 . If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature onOctober 15, 2022 , the aggregate amount of those notes exceeds$100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, orJuly 16, 2022 . Also included in notes payable is interest on$21.0 million irrevocable letters of credit, which will continue decrease ratably per month until expiring inAugust 2021 . Interest accrues at 3.25% and 0.125% per annum for participation fees and fronting fees, respectively. (2)The payment dates could be accelerated. See the "Going Concern" section in Note 2 of the notes to the consolidated financial statements for additional information. (3)The aggregate principal amount of our 7.0% Senior Notes is$350.0 million . We are obligated to make semi-annual interest payments through maturity onOctober 15, 2022 equal to$12.3 million . See Note 5 of the notes to the consolidated financial statements for additional information. (4)The aggregate principal amount of our 8.75% Senior Notes is$275.0 million . We are obligated to make semi-annual interest payments through maturity onJune 15, 2025 equal to$12.0 million . See Note 5 of the notes to the consolidated financial statements for additional information. (5)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the pipeline. (6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations. (7)Derivative liability represents the net fair value for oil, gas, and NGL commodity derivatives presented as liabilities in our Consolidated Balance Sheets as ofDecember 31, 2020 . The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" 49 -------------------------------------------------------------------------------- Table of Contents below and "Commodity Hedging Activities" above for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments. (8)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property. (9)Includes$10.2 million for the year endedDecember 31, 2022 and$15.3 million for the year endedDecember 31, 2023 related to a drilling commitment with a joint interest partner which requires us to drill and complete two wells byJuly 2022 and three wells by 2023. If the drilling commitment is not met, we must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. The Company is also party to minimum volume commitments for the delivery of natural gas volumes to midstream entities for gathering, processing and capital reimbursements as well as minimum volume commitments to purchase fresh water from water suppliers. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as of
Trends and Uncertainties
Regulatory Trends. Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability to conduct, and increases the costs of conducting, our operations. Areas in which we operate are subject to federal, state and local regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and increase the costs of such permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets. Efforts related to climate change organized around a "keep it in the ground" message have gained traction inNew York and other coastal states, as well as internationally, notably inFrance andGermany . The movement has found some success in persuading governments, investors and corporations to consider measures to reduce the use of fossil fuels in the future. Examples include local measures to prohibit the use of natural gas for heating, hot water and stoves in new construction;GM's announcement that it will phase-out gasoline engines in its cars by 2035; and increased pressure on corporations to reduce emissions from the investment community, notably Black Rock and Vanguard. These developments portend a risk that demand for fossil fuels may be significantly reduced in the coming decades. See "Business and Properties-Operations-Environmental Matters and Regulation" for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.
The following trends and uncertainties are related to the COVID-19 pandemic:
Declining Commodity Prices. Energy prices declined sharply during the first half of 2020 due to the COVID-19 pandemic. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year endedDecember 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. As ofFebruary 4, 2021 , we have hedged 3,098,000 barrels and 365,000 barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively. However, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. This uncertainty increases the volatility and amplitude of risks we face as described in "Item 1A. Risk Factors". If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.Employee Health and Safety. The health and safety of our employees and the community is our highest priority. We are also cognizant that supplying reliable energy to our communities and the nation is an essential function. The federal government, through theCybersecurity and Infrastructure Security Administration , as well asColorado state and local "stay-at-home" orders, have provided exemptions for oil and gas workers. 50 -------------------------------------------------------------------------------- Table of Contents Under our business continuity plan, we were rapidly able to switch to remote operations in response to the COVID-19 pandemic in early March. We successfully transitioned to full remote access and operations, in both theDenver headquarters office and at the field level. The successful transition to remote operations was virtually seamless. Frommid-March 2020 throughFebruary 2021 , based on management's continuous risk assessments, employees were either fully remote or on a staggered schedule so that approximately 50% of the work force was in the office on a daily basis. SupplyChain Issues . We have not experienced any recent challenges with respect to obtaining oil field goods and services. However, as oil service and supply companies cut work force and stack rigs and frac fleets, there is the potential for challenges on this front when activity begins to ramp up, although the related timing is highly uncertain. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted inthe United States . The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the notes to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Our oil, natural gas and NGL exploration and production activities are accounted
for using the successful efforts method. Under this method, all property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved
reserves. If an exploratory well does not find proved reserves, the costs of
drilling the well are charged to expense and remain within cash flows from
investing activities in the Consolidated Statements of Cash Flows. If an
exploratory well does find proved reserves, the costs remain capitalized, are
included within additions to oil and gas properties and remain within cash flows
from investing activities in the Consolidated Statements of Cash Flows. The
costs of development wells are capitalized whether proved reserves are added or
not. All exploratory wells are evaluated for economic viability within one year
of well completion, and the related capitalized costs are reviewed quarterly.
Exploratory wells that discover potentially economic reserves in areas where a
major capital expenditure would be required before production could begin and
where the economic viability of that major capital expenditure depends upon the
successful completion of further exploratory work in the area remain capitalized
if the well finds a sufficient quantity of reserves to justify its completion as
a producing well, and we are making sufficient progress assessing the reserves
and the economic and operating viability of the project. Oil and gas lease
acquisition costs are also capitalized. Upon sale or retirement of depreciable
or depletable property, the cost and related accumulated DD&A are eliminated
from the accounts and the resulting gain or loss is recognized. Interest cost is
capitalized as a component of property cost for significant exploration and
development projects that require greater than six months to be readied for
their intended use.
The application of the successful efforts method of accounting requires
managerial judgment to determine the proper classification of wells designated
as developmental or exploratory, which will ultimately determine the proper
accounting treatment of the costs incurred. In addition to development on
exploratory wells, we may drill scientific wells that are only used for data
gathering purposes. The costs associated with these scientific wells are
expensed as incurred as exploration expense. The results from a drilling
operation can take considerable time to analyze, and the determination that
commercial reserves have been discovered requires both judgment and industry
experience.
Other exploration costs, including certain geological and geophysical expenses
and delay rentals for oil and gas leases, are charged to expense as incurred.
The sale of a partial interest in a proved property is accounted for as a cost
recovery and no gain or loss is recognized as long as this treatment does not
significantly affect the unit-of-production amortization rate. Maintenance and
repairs are charged to expense, and renewals and settlements are capitalized to
the appropriate property and equipment accounts.
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Unproved oil and gas property costs are transferred to proved oil and gas
properties if the properties are subsequently determined to be productive or are
assigned proved reserves. Proceeds from sales of partial interests in unproved
leases are accounted for as a recovery of cost without recognizing any gain
until all costs are recovered. Unproved oil and gas properties are assessed
periodically for impairment based on remaining lease terms, drilling results,
reservoir performance, commodity price outlooks, future plans to develop
acreage, recent sales prices of comparable properties and other relevant
matters.
We review our oil and natural gas properties for impairment on a quarterly basis
or whenever events and circumstances indicate that a decline in the
recoverability of their carrying value may have occurred. We estimate the
expected undiscounted future net cash flows of our oil and gas properties using
proved and risked probable and possible reserves based on our development plans
and best estimate of future production, commodity pricing, reserve risking,
gathering and transportation deductions, production tax rates, lease operating
expenses and future development costs. We compare such undiscounted future net
cash flows to the carrying amount of the oil and gas properties to determine if
the carrying amount is recoverable. If the undiscounted future net cash flows
exceed the carrying amount of the oil and gas properties, no impairment is
taken. If the carrying amount of a property exceeds the undiscounted future net
cash flows, we will impair the carrying value to fair value as of the applicable
measurement date. The factors used to determine fair value may include, but are
not limited to, recent sales prices of comparable properties, indications from
marketing activities, the present value of future revenues, net of estimated
operating and development costs using estimates of reserves, future commodity
pricing, future production estimates, anticipated capital expenditures and
various discount rates commensurate with the risk and current market conditions
associated with realizing the projected cash flows.
Oil and gas properties are assessed for impairment once they meet the criteria
to be classified as held for sale. Assets held for sale are carried at the lower
of carrying cost or fair value less costs to sell. The fair value of the assets
is determined using a market approach, based on an estimated selling price, as
evidenced by current marketing activities, if possible. If an estimated selling
price is not available, we utilize the income valuation technique, which
involves calculating the present value of future net cash flows, as discussed
above. If the carrying amount of the assets exceeds the fair value less costs to
sell, an impairment will result to reduce the value of the properties down to
fair value less costs to sell. The estimated fair value of assets held for sale
may be materially different from sales proceeds that we eventually realize due
to a number of factors including but not limited to the differences in expected
future commodity pricing, location and quality differentials, our relative
desire to dispose of such properties based on facts and circumstances impacting
our business at the time we agree to sell, such as our position in the field
subsequent to the sale and plans for future acquisitions or development in core
areas.
Our investment in producing oil and natural gas properties includes an estimate
of the future costs associated with dismantlement, abandonment and restoration
of our properties. The present value of the estimated future costs to dismantle,
abandon and restore a well location is added to the capitalized costs of our oil
and gas properties and recorded as a long-term liability. The capitalized cost
is included in the oil and natural gas property costs that are depleted over the
life of the assets.
The provision for depletion of oil and gas properties is calculated on a
field-by-field basis using the units-of-production method. Natural gas and NGLs
are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one
Boe and forty-two gallons to one Boe, respectively. Our rate of recording DD&A
is dependent upon our estimates of total proved and proved developed reserves,
which incorporate assumptions regarding future development and abandonment costs
as well as our level of capital spending. If the estimates of total proved or
proved developed reserves decline, the rate at which we record DD&A expense
increases, reducing our net income. This decline may result from lower market
prices, which may make it uneconomic to drill for and produce higher cost
fields. We are unable to predict changes in reserve quantity estimates as such
quantities are dependent on the success of our exploitation and development
program, as well as future economic conditions.
Oil and Gas Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves estimates are audited on a well-by-well basis by an independent third party engineering firm. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates as ofDecember 31, 2020 . Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance withSEC guidelines. Our independent third party engineering firm adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the 52 --------------------------------------------------------------------------------
interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.
The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Please refer to the reserve disclosures in "Items 1 and 2 - Business and Properties" for further detail on reserves data.
Revenue Recognition
All of our sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when we satisfy our performance obligations and the customer obtains control of the product. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, we do not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers do not require us to constrain variable consideration for accounting purposes. Our contracts with customers typically require payment within one month of delivery. Under our contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product. Our oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues in the Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Consolidated Statements of Operations. Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.
Income Taxes and Uncertain Tax Positions
Income taxes are provided for the tax effects of transactions reported in the
financial statements and consist of taxes currently payable plus deferred income
taxes related to certain income and expenses recognized in different periods for
financial and income tax reporting purposes. Deferred income tax assets and
liabilities represent the future tax return consequences of those differences,
which will either be taxable or deductible when assets are recovered or
liabilities are settled. Deferred income taxes are also recognized for net
operating loss carry forwards and tax credits that are available to offset
future income taxes. Deferred income taxes are measured by applying currently
enacted tax rates to the differences between financial statement and income tax
reporting. We routinely assess the realizability of our deferred tax assets. If
we conclude that it is more likely than not that some portion or all of the
deferred tax assets will not be realized under accounting standards, the tax
asset would be reduced by a valuation allowance. We consider estimated future
taxable income in making such assessments, including the future reversal of
taxable temporary differences. Numerous judgments and assumptions are inherent
in the determination of future taxable income, including factors such as future
operating conditions (particularly as related to prevailing oil and natural gas
prices). There can be no assurance that facts and circumstances will not
materially change and require us to adjust deferred tax asset valuation
allowances in the future.
Accounting guidance for recognizing and measuring uncertain tax positions
prescribes a more likely than not recognition threshold that a tax position must
meet for any of the benefit of the uncertain tax position to be recognized in
the financial statements. Guidance is also provided regarding de-recognition,
classification and disclosure of these uncertain tax positions. Based on this
guidance, we regularly analyze tax positions taken or expected to be taken in a
tax return based on the threshold
53
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prescribed. Tax positions that do not meet or exceed this threshold are
considered uncertain tax positions. Penalties, if any, related to uncertain tax
positions would be recorded in other expenses. We currently do not have any
uncertain tax positions recorded as of
We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be. See "Results of Operations- Income Tax (Expense) Benefit" above for a discussion of changes to the valuation allowance during 2020.
New Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Summary of Significant Accounting Policies in Note 2 of the notes to the consolidated financial statements.
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